A plunger lift is an apparatus that can be used to increase the productivity of oil and gas wells. In the early stages of a well's life, liquid loading may not be a problem. When production rates are high, well liquids are typically carried out of the well tubing by high velocity gas. As a well declines and production decreases, a critical velocity is reached wherein heavier liquids may not make it to the surface and start falling back to the bottom of the well exerting pressure on the formation, thus loading up the well. As a result, the gas being produced by the formation can no longer carry the liquid being produced to the surface. As gas flow rate and pressures decline in a well, lifting efficiency can decline substantially.
Well loading typically occurs for two reasons. First, as liquid comes in contact with the wall of the production string of tubing, friction slows the velocity of the liquid. Some of the liquid may adhere to the tubing wall, creating a film of liquid on the tubing wall which does not reach the surface. Second, as the liquid velocity continues to slow, the gas phase may no longer be able to support liquid in either a slug form or a droplet form. Along with the liquid film on the sides of the tubing, a slug or droplet(s) may begin to fall back to the bottom of the well. In an advanced situation there will be liquid accumulated in the bottom of the well. The produced gas must bubble through the liquid at the bottom of the well and then flow to the surface. However, as gas advances through the accumulated liquid, the gas may proceed at a low velocity. Thus, little liquid, if any, may be carried to the surface by the gas, resulting in only a small amount of gas being produced at the surface.
A plunger lift system can act to remove accumulated liquid in a well. That is, a plunger lift may unload a gas well and, in some instances, unload the gas well without interrupting production. A plunger lift system utilizes gas present within the well as a system driver. A plunger lift system works by cycling a plunger into and out of the well. During a cycle, a plunger typically descends to the bottom of a well passing through fluids within the well. Once the liquids are above the plunger, these liquids may be picked up or lifted by the plunger and brought to the surface, thus removing most or all liquids in the production tubing. The gas below the plunger will push both the plunger and the liquid on top of the plunger to the surface completing the plunger cycle. As liquid is removed from the tubing bore, an otherwise impeded volume of gas can begin to flow from a producing well. The plunger can also keep the tubing free of paraffin, salt or scale build-up.
In certain wells, fluid buildup hampers the decent of the plunger to the well bottom. Thus, wells with a high fluid level (e.g., high gas flow rates and/or high liquid accumulations) tend to lessen well production by increasing the cycle time of the plunger lift system, specifically by increasing the plunger descent time to the well bottom. Prior art designs have utilized two-piece plungers having a ball and sleeve arrangement to reduce decent time to the well bottom. Typically, the ball portion of the plunger is received in a lower end of a hollow sleeve portion of the plunger wherein the ball and sleeve unite at the well bottom. Once united, the ball is disposed in a lower opening of the sleeve and prevents fluid passage there through. At this time, gas beneath the united two-piece plunger accumulates and raises the plunger through the well. Further, the gas pressure beneath the united plunger maintains the ball within the lower opening of the sleeve. At the surface, the united two-piece plunger is received in a lubricator where an extracting rod passes through the sleeve and dislodges the ball. The ball is then free to fall to the bottom of the well. The sleeve is typically held in the lubricator for a time by flow from the well or by mechanical engagement. Once released, the sleeve falls to the well bottom where it unites with the ball.
While ball and sleeve plunger improve the cycle time in high flow wells, these ball and sleeve plungers provide little benefit once flow of the well decreases. That is, such ball and sleeve plungers are primarily utilized for the first few months of a well's production. After this time, multiple alternate plungers (e.g., by-pass, one-piece) may be utilized with the reduced flow rates. However, changing from a ball and sleeve plunger to another plunger type typically requires reconfiguring the lubricator to remove the extraction rod that is necessary for use with a ball and sleeve plunger.